Without limiting the scope of the present invention, its background will be described with reference to using rotary drill bits to drill a well that traverses a subterranean hydrocarbon bearing formation, as an example.
Rotary drill bits are commonly used to drill wells in the oil and gas well drilling industry as these rotary drill bit offers a satisfactory rate of penetration with a significant operational life in drilling most commonly encountered formations. Typically, a rotary drill bit includes a bit body having a threaded pin at its upper end adapted to be detachably secured to a drill string suspended from a drill rig. In addition, a rotary drill bit generally has a plurality of depending legs, typically three such legs, at the lower end of the body. The drill bit further includes a plurality of conical roller cutters having cutting elements thereon, with one roller cutter on each leg. Each leg typically includes a bearing for rotatably mounting each roller cutter thereon.
Sealed bearing type roller cutter bits further have a lubrication system including a reservoir holding a supply of lubricant. A passage in the bit body extends from the reservoir to the bearing to allow flow of lubricant to the bearing. A seal is disposed between the roller cutter and the bearing journal that holds lubricant in the bit. A diaphragm at the reservoir provides pressure compensation between the lubricant and the drilling fluid in the annulus between the bit and the wellbore.
In use, roller cutter drill bits are rotated in the wellbore on the end of a drill string that applies a relatively high downward force onto the drill bit. As the bits are rotated, the conical roller cutters rotate on the bearing journals thereby bringing the cutting elements on the roller cutters into engagement with the substrate at the bottom of the wellbore. The cutting elements drill through the substrate at the wellbore bottom by applying high point loads to the substrate to thereby cause the substrate to crack or fracture from the compression. A drilling fluid, commonly called drilling mud, passes under pressure from the surface through the drill string to the drill bit and is ejected from one or more nozzles adjacent to the roller cutters. The drilling fluid cools the drill bit and carries the cuttings up the wellbore annulus to the surface.
For cost-effective drilling, a worn drill bit needs to be replaced due to the reduced rate of drilling penetration for the worn bit. At a certain point, the cost of replacing the old drill bit with a new bit becomes equal to the cost of the drilling inefficiency, or in other words, the cost of the new bit plus the cost of rig time in tripping the drill string in and out of the wellbore is less than the cost of operating the worn bit. Unfortunately, once a drill bit is positioned in a wellbore, gathering reliable information regarding the operating condition, performance and remaining useful life of the drill bit becomes difficult. Typically, the decision by a drilling rig operator to replace a drill bit is a subjective one, based upon experience and general empirical data showing the performance of similar drill bits in drilling similar substrate formations. The rig operator's decision, however, as to when to replace a drill bit is often not the most cost effective because of the many factors affecting drilling performance beyond the condition and performance of the bit itself.
In addition, it is not uncommon for a drill bit to fail during the drilling operation. Bit failure may occur due to a variety of factors. For example, a bit may fail due to an improper application of the bit, such as by excessive weight on the drill bit from the drilling string, excessive rotational speed, using the wrong type of bit for substrate being drilled and the like. Regardless of the cause, the two most common types of bit failures are breakage of the cutting elements and bearing failure.
In the first mode, pieces of the cutting elements, which are typically either steel teeth or tungsten carbide inserts, are broken from the roller cutters. This breakage does not normally stop the drilling action but it does significantly reduce the rate of drilling penetration. In addition, the broken pieces are typically carried out of the wellbore by the circulating drilling fluid, thereby leaving the wellbore bottom clean for a replacement bit to continue extending the wellbore.
In the second mode of failure, once a bearing assembly has failed, continued use of the bit may result in the roller cutter separating from the bearing journal and remaining in the wellbore when the drill string is retrieved to the surface. The lost roller cutter must then be retrieved from the wellbore in a time-consuming and expensive fishing operation in which a special retrieval tool is tripped in and out of the wellbore to retrieve the broken roller cutter.
In sealed bearing roller cutter bits, bearing failure is often the result of a seal failure that allows lubricant to flow out of the drill bit and drilling fluid, which contains abrasive particles, to flow into the bearing. Although less common, diaphragm failure has the same result as seal failure. In any event, bearing failure is almost always preceded by, or at least accompanied by, a loss of lubricant.
Therefore, a need has arisen for an improved seal for a sealed bearing roller cutter bit that can maintain the lubricant within the drill bit and prevent the flow of drilling fluid into the bearing. A need has also arisen for such a seal that has a high resistance to heat and abrasion, has a low coefficient of friction and does not significantly deform under load. Further, need has arisen for such a seal that is resistant to chemical interaction with hydrocarbons fluids encountered within the wellbore and that has a long useful life.